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EX-10 - EXHIBIT 10.21 - DAYBREAK OIL & GAS, INC.exhibit1021.htm
EX-10 - EXHIBIT 10.20 - DAYBREAK OIL & GAS, INC.exhibit1020.htm
EX-32 - EXHIBIT 32.1 - DAYBREAK OIL & GAS, INC.exhibit321.htm
EX-31 - EXHIBIT 31.1 - DAYBREAK OIL & GAS, INC.exhibit311.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


FORM 10-Q


(Mark One)


x          QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the quarterly period ended November 30, 2015


OR


o          TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934


For the transition period from   ______________   to   _______________


Commission File Number: 000-50107


DAYBREAK OIL AND GAS, INC.

(Exact name of registrant as specified in its charter)


Washington

 

91-0626366

(State or other jurisdiction of incorporation or organization)

 

(I.R.S. Employer Identification No.)

 

 

 

1101 N. Argonne Road, Suite A 211, Spokane Valley, WA

 

99212

(Address of principal executive offices)

 

(Zip code)


(509) 232-7674

(Registrant’s telephone number, including area code)


 

 

 

(Former name, former address and former fiscal year, if changed since last report)


Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   þ Yes   ¨ No


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes þ   No ¨


Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨

 

Accelerated filer ¨

 

 

 

Non-accelerated filer   ¨

(Do not check if a smaller reporting company)

Smaller reporting company þ


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).   ¨ Yes   þ No


At January 12, 2016 the registrant had 51,487,373 outstanding shares of $0.001 par value common stock.










TABLE OF CONTENTS



PART I - FINANCIAL INFORMATION


ITEM 1.

FINANCIAL STATEMENTS

3

 

Balance Sheets at November 30, 2015 and February 28, 2015 (Unaudited)

3

 

Statements of Operations for the Three and Nine Months Ended November 30, 2015 and November 30, 2014 (Unaudited)

4

 

Statements of Cash Flows for the Nine Months Ended November 30, 2015 and November 30, 2014 (Unaudited)

5

 

NOTES TO UNAUDITED FINANCIAL STATEMENTS

6

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

15

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

32

ITEM 4.

CONTROLS AND PROCEDURES

32

 

 

 

 

PART II - OTHER INFORMATION

 

 

 

 

ITEM 1.

LEGAL PROCEEDINGS

33

ITEM 1A.

RISK FACTORS

33

ITEM 6.

EXHIBITS

34

Signatures

 

35





2





PART I

FINANCIAL INFORMATION


ITEM 1.  FINANCIAL STATEMENTS


DAYBREAK OIL AND GAS, INC.

Balance Sheets – Unaudited

 

As of November 30,

 

As of February 28,

 

2015

 

2015

ASSETS

 

 

 

 

 

CURRENT ASSETS:

 

 

 

 

 

Cash and cash equivalents

$

108,646 

 

$

496,772 

Accounts receivable:

 

 

 

 

 

Oil and natural gas sales

 

119,555 

 

 

202,732 

Joint interest participants

 

62,934 

 

 

51,382 

Other receivables, net

 

101,003 

 

 

160,996 

Production revenue receivable – current

 

65,000 

 

 

120,000 

Prepaid expenses and other current assets

 

254,649 

 

 

201,693 

Note receivable – current

 

642,540 

 

 

1,320,944 

Total current assets

 

1,354,327 

 

 

2,554,519 

OIL AND NATURAL GAS PROPERTIES, successful efforts method, net

 

 

 

 

 

Proved properties

 

4,209,511 

 

 

4,379,606 

Unproved properties

 

700,805 

 

 

733,478 

PREPAID DRILLING COSTS

 

16,452 

 

 

16,452 

PRODUCTION REVENUE RECEIVABLE – NON-CURRENT

 

 

 

35,000 

DEFERRED FINANCING COSTS, NET

 

748,599 

 

 

1,058,751 

NOTE RECEIVABLE – NON-CURRENT

 

3,738,296 

 

 

3,429,056 

OTHER ASSETS

 

106,263 

 

 

106,199 

Total assets

$

10,874,253 

 

$

12,313,061 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ DEFICIT

 

 

 

 

 

CURRENT LIABILITIES:

 

 

 

 

 

Accounts payable and other accrued liabilities

$

1,634,331 

 

$

1,435,677 

Accounts payable – related parties

 

963,716 

 

 

905,891 

Accrued interest

 

188,290 

 

 

158,797 

Notes payable – related party

 

250,100 

 

 

250,100 

Debt – current portion, net

 

3,315,906 

 

 

4,691,211 

Line of credit

 

853,136 

 

 

869,865 

Total current liabilities

 

7,205,479 

 

 

8,311,541 

LONG TERM LIABILITIES:

 

 

 

 

 

12% Notes payable, net

 

315,000 

 

 

315,000 

12% Notes payable – related party, net

 

250,000 

 

 

250,000 

Debt – non-current portion, net

 

10,138,706 

 

 

8,591,507 

Asset retirement obligation

 

31,873 

 

 

29,603 

Total liabilities

 

17,941,058 

 

 

17,497,651 

COMMITMENTS AND CONTINGENCIES

 

 

 

 

 

STOCKHOLDERS’ DEFICIT:

 

 

 

 

 

Preferred stock – 10,000,000 shares authorized, $0.001 par value;

 

 

 

Series A Convertible Preferred stock – 2,400,000 shares authorized, $0.001 par value, 6% cumulative dividends; 724,565 and 734,565 shares issued and outstanding, respectively

 

725 

 

 

735 

Common stock – 200,000,000 shares authorized; $0.001 par value, 51,487,373 and 51,457,373 shares issued and outstanding, respectively

 

51,487 

 

 

51,457 

Additional paid-in capital

 

22,968,714 

 

 

22,968,734 

Accumulated deficit

 

(30,087,731)

 

 

(28,205,516)

Total stockholders’ deficit

 

(7,066,805)

 

 

(5,184,590)

Total liabilities and stockholders’ deficit

$

10,874,253 

 

$

12,313,061 



The accompanying notes are an integral part of these unaudited financial statements




3






DAYBREAK OIL AND GAS, INC.

Statements of Operations – Unaudited

 

For the Three Months Ended

November 30,

 

For the Nine Months Ended

November 30,

 

2015

 

2014

 

2015

 

2014

REVENUE:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

$

276,332 

 

$

663,650 

 

$

1,087,450 

 

$

2,518,375 

 

 

 

 

 

 

 

 

 

 

 

 

OPERATING EXPENSES:

 

 

 

 

 

 

 

 

 

 

 

Production expenses

 

62,637 

 

 

86,140 

 

 

208,243 

 

 

251,625 

Exploration and drilling

 

9,756 

 

 

7,362 

 

 

29,823 

 

 

20,172 

Depreciation, depletion, amortization, and impairment

 

141,969 

 

 

134,873 

 

 

399,698 

 

 

426,366 

General and administrative

 

248,357 

 

 

230,040 

 

 

782,860 

 

 

849,964 

Total operating expenses

 

462,719 

 

 

458,415 

 

 

1,420,624 

 

 

1,548,127 

OPERATING INCOME (LOSS)

 

(186,387)

 

 

205,235 

 

 

(333,174)

 

 

970,248 

 

 

 

 

 

 

 

 

 

 

 

 

OTHER INCOME (EXPENSE):

 

 

 

 

 

 

 

 

 

 

 

Interest income

 

339,096 

 

 

378,932 

 

 

763,700 

 

 

833,778 

Interest expense

 

(982,270)

 

 

(718,586)

 

 

(2,312,741)

 

 

(2,081,590)

Total other income (expense)

 

(643,174)

 

 

(339,654)

 

 

(1,549,041)

 

 

(1,247,812)

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS)

 

(829,561)

 

 

(134,419)

 

 

(1,882,215)

 

 

(277,564)

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative convertible preferred stock dividend requirement

 

(32,514)

 

 

(33,097)

 

 

(98,410)

 

 

(100,020)

 

 

 

 

 

 

 

 

 

 

 

 

NET INCOME (LOSS) AVAILABLE TO COMMON SHAREHOLDERS

$

(862,075)

 

$

(167,516)

 

$

(1,980,625)

 

$

(377,584)

NET INCOME (LOSS) PER COMMON SHARE

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted

$

0.02 

 

$

(0.00)

 

$

(0.04)

 

$

(0.01)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING

 

 

 

 

 

 

 

 

 

 

 

Basic and diluted

 

51,487,373 

 

 

51,448,373 

 

 

51,484,073 

 

 

55,035,219 



The accompanying notes are an integral part of these unaudited financial statements




4





DAYBREAK OIL AND GAS, INC.

Statements of Cash Flows – Unaudited

 

Nine Months Ended

 

November 30,

2015

 

November 30,

2014

CASH FLOWS FROM OPERATING ACTIVITIES:

 

 

 

 

 

Net loss

$

(1,882,215)

 

$

(277,564)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

 

 

 

 

 

Stock compensation

 

 

 

2,515 

Depreciation, depletion, accretion and impairment expense

 

399,698 

 

 

426,366 

Amortization of debt discount

 

100,896 

 

 

127,960 

Amortization of deferred financing costs

 

319,808 

 

 

316,126 

Interest income

 

(64)

 

 

(64)

Changes in assets and liabilities:

 

 

 

 

 

Accounts receivable – oil and natural gas sales

 

83,177 

 

 

82,071 

Accounts receivable – joint interest participants

 

(11,552)

 

 

246,367 

Accounts receivable – other

 

(258,343)

 

 

(98,558)

Prepaid expenses and other current assets

 

(52,956)

 

 

(160,096)

Accounts payable and other accrued liabilities

 

111,258 

 

 

(505,498)

Accounts payable – related parties

 

57,825 

 

 

(100,386)

Accrued interest

 

693,921 

 

 

195,406 

Net cash provided by (used in) operating activities

 

(438,547)

 

 

254,645 

 

 

 

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES:

 

 

 

 

 

Additions to oil and natural gas properties

 

(107,263)

 

 

(1,285,857)

Prepaid drilling costs

 

 

 

(184,227)

Additions to note receivable

 

 

 

(4,725,000)

Collections of note receivable

 

777,500 

 

 

2,806,710 

Deferred interest

 

 

 

655 

Net cash provided by (used in) investing activities

 

670,237 

 

 

(3,387,719)

 

 

 

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES:

 

 

 

 

 

Proceeds from long-term debt

 

25,000 

 

 

5,700,000 

Payments on long-term debt

 

(618,431)

 

 

(2,202,910)

Proceeds from warrant conversion

 

 

 

7,000 

Payment of deferred financing fees

 

(9,656)

 

 

(345,000)

Payments on line of credit

 

(16,729)

 

 

(5,421)

Net cash provided by (used in) financing activities

 

(619,816)

 

 

3,153,669 

 

 

 

 

 

 

NET DECREASE IN CASH AND CASH EQUIVALENTS

 

(388,126)

 

 

20,595 

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD

 

496,772 

 

 

500,431 

CASH AND CASH EQUIVALENTS AT END OF PERIOD

$

108,646 

 

$

521,026 

 

 

 

 

 

 

CASH PAID FOR:

 

 

 

 

 

Interest

$

1,862,544 

 

$

1,465,881 

Income taxes

$

 

$

 

 

 

 

 

 

SUPPLEMENTAL CASH FLOW INFORMATION:

 

 

 

 

 

Unpaid additions to oil and natural gas properties

$

87,396 

 

$

3,702 

Conversion of warrants

$

 

$

1,874 

Share-to-warrant exchange

$

 

$

428 

Increase in note receivable for interest added to principal

$

408,336 

 

$

Increase converted to principal on long term debt

$

664,428 

 

$

ARO asset and liability increase

$

140 

 

$

2,428 

Increase in note payable for stock acquisition and subsequent retirement

$

 

$

1,708,447 

Transfer agent balancing adjustment

 

 

 

140 

Conversion of preferred stock to common stock

$

30 

 

$

Repurchase of stock through payment of payroll taxes

$

 

$

490 



The accompanying notes are an integral part of these unaudited financial statements






5





DAYBREAK OIL AND GAS, INC.

NOTES TO UNAUDITED FINANCIAL STATEMENTS



NOTE 1 — ORGANIZATION AND BASIS OF PRESENTATION:


Organization


Originally incorporated as Daybreak Uranium, Inc., (“Daybreak Uranium”) under the laws of the State of Washington on March 11, 1955, Daybreak Uranium was organized to explore for, acquire, and develop mineral properties in the Western United States.  During 2005, management of the Company decided to enter the oil and natural gas exploration and production industry.  On October 25, 2005, the Company shareholders approved a name change from Daybreak Mines, Inc. to Daybreak Oil and Gas, Inc. (referred to herein as “Daybreak” or the “Company”) to better reflect the business of the Company.


All of the Company’s oil and natural gas production is sold under contracts which are market-sensitive. Accordingly, the Company’s financial condition, results of operations, and capital resources are highly dependent upon prevailing market prices of, and demand for, oil and natural gas.  These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond the control of the Company.  These factors include the level of global demand for petroleum products, foreign supply of oil and natural gas, the establishment of and compliance with production quotas by oil-exporting countries, the relative strength of the U.S. dollar, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic.


Basis of Presentation


The accompanying unaudited interim financial statements and notes for the Company have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q for quarterly reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”).  Accordingly, they do not include all of the information and footnote disclosures normally required by accounting principles generally accepted in the United States of America for complete financial statements.


In the opinion of management, all adjustments considered necessary for a fair presentation of the financial statements have been included and such adjustments are of a normal recurring nature.  Operating results for the nine months ended November 30, 2015 are not necessarily indicative of the results that may be expected for the fiscal year ending February 29, 2016.


These financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the fiscal year ended February 28, 2015.


Use of Estimates


In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions.  These estimates and assumptions may affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and revenues and expenses during the reporting period.  Actual results could differ materially from those estimates. The accounting policies most affected by management’s estimates and assumptions are as follows:

·

The reliance on estimates of proved reserves to compute the provision for depreciation, depletion and amortization and to determine the amount of any impairment of proved properties;

·

The valuation of unproved acreage and proved oil and natural gas properties to determine the amount of any impairment of oil and natural gas properties;

·

Judgment regarding the productive status of in-progress exploratory wells to determine the amount of any provision for abandonment; and

·

Estimates regarding abandonment obligations.


Reclassifications


Certain reclassifications have been made to conform the prior period’s financial information to the current period’s presentation.  These reclassifications had no effect on previously reported net loss or accumulated deficit.




6






NOTE 2 — GOING CONCERN:


Financial Condition


The Company’s financial statements for the nine months ended November 30, 2015 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  The Company has incurred net losses since entering the oil and natural gas exploration industry and as of November 30, 2015 has an accumulated deficit of $30,087,731 and a working capital deficit of $5,851,152 which raises substantial doubt about the Company’s ability to continue as a going concern.


Management Plans to Continue as a Going Concern


The Company continues to implement plans to enhance its ability to continue as a going concern.  Daybreak currently has a net revenue interest in 20 producing oil wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue.  The Company’s average working interest in these wells is 36.6% and the average net revenue interest (“NRI”) is 28.4% for these same wells.


Additionally, the Company has become involved in a shallow oil development project in an existing natural gas field in Lawrence County, Kentucky, through its acquisition of an average 25% working interest in approximately 7,300 acres in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky.  Daybreak currently has 14 producing horizontal oil wells in the Twin Bottoms Field with some supplementary natural gas production.  The Company’s average working interest in these 14 horizontal oil wells is 22.6% and the average NRI is 19.7% in these same wells.


The Company anticipates revenues will continue to decrease from lower hydrocarbon prices even as it participates in the drilling of more wells in California and Kentucky.  Daybreak plans to continue its development drilling programs in both Kentucky and California at a rate that is compatible with its cash flow; funding opportunities and hydrocarbon prices.


The Company’s sources of funds in the past have included the debt and equity markets and select asset sales.  The Company has experienced revenue growth that has resulted in positive cash flow in the past from its oil and natural gas properties, however, it has not yet established consistent positive cash flow on a company-wide basis primarily due to lower oil prices.  The Company has hired an investment banking firm to assist in refinancing its current debt to more favorable terms and secure additional capital to continue to develop its properties in Kentucky and California.  As part of the efforts to refinance its debt, the Company may seek additional funding from the equity markets.  However, the Company cannot offer any assurance that it will be successful in executing the aforementioned plan to continue as a going concern.


Daybreak’s financial statements as of November 30, 2015 do not include any adjustments that might result from the inability to implement or execute Daybreak’s plans to improve our ability to continue as a going concern.



NOTE 3 RECENT ACCOUNTING PRONOUNCEMENTS:


There are no new accounting pronouncements issued or effective that have had, or are expected to have, a material impact on the Company’s financial statements.



NOTE 4 CONCENTRATION OF CREDIT RISK:


Substantially all of the Company’s trade accounts receivable result from crude oil and natural gas sales or joint interest billings to its working interest partners.  This concentration of customers and joint interest owners may impact the Company’s overall credit risk as these entities could be affected by similar changes in economic conditions including lower oil prices as well as other related factors.  Trade accounts receivable are generally not collateralized.  There were no allowances for doubtful accounts for the Company’s trade accounts receivable at November 30, 2015 and February 28, 2015, as all joint interest owners have a history of paying their obligations.


At the Company’s East Slopes project in California, there is only one buyer available for the purchase of all oil production.  At the Company’s Twin Bottoms Field project located in Lawrence County, Kentucky, there is only one buyer available for the purchase of its oil production and only one buyer available for the purchase of its natural gas production.  At November 30, 2015 and February 28, 2015 these three individual customers represented 100.0% of crude oil and natural gas revenue accounts receivable.  If these buyers



7






are unable to resell their products or if they lose a significant sales contract then the Company may incur difficulties in selling its oil and natural gas production.


The Company’s accounts receivable from Kentucky and California oil and natural gas sales at November 30, 2015 and February 28, 2015 are set forth in the table below.


 

 

 

 

November 30, 2015

 

February 28, 2015

Project

 

Customer

 

Revenue

Receivable

 

Percentage

 

Revenue

Receivable

 

Percentage

Kentucky – Twin Bottoms Field (Oil)

 

Appalachian Oil

 

$

37,640

 

31.5%

 

$

90,906

 

44.9%

Kentucky – Twin Bottoms Field (Natural gas)

 

Jefferson Gas

 

 

6,674

 

5.6%

 

 

16,676

 

8.2%

California – East Slopes Project (Oil)

 

Plains Marketing

 

 

75,241

 

62.9%

 

 

95,150

 

46.9%

 

 

 

 

$

119,555

 

100.0%

 

$

202,732

 

100.0%


Other receivables balances primarily include amounts advanced to certain minority working interest partners in Kentucky and monthly principal and interest receivable on the loan to App Energy, LLC, a Kentucky limited liability company (“App Energy”). For additional information on the App Energy loan refer to the discussion in Note 8 – Note Receivable.



NOTE 5 — OIL AND NATURAL GAS PROPERTIES:


Oil and natural gas property balances at November 30, 2015 and February 28, 2015 are set forth in the table below.


 

November 30, 2015

 

February 28, 2015

Proved leasehold costs

$

700,573 

 

$

695,231 

Unproved leasehold costs

 

700,805 

 

 

733,478 

Costs of wells and development

 

591,576 

 

 

542,563 

Capitalized exploratory well costs

 

5,447,249 

 

 

5,308,876 

Total cost of oil and natural gas properties

 

7,440,203 

 

 

7,280,148 

Accumulated depletion, depreciation, amortization and impairment

 

(2,529,887)

 

 

(2,167,064)

Net oil and natural gas properties

$

4,910,316 

 

$

5,113,084 



NOTE 6PRODUCTION REVENUE RECEIVABLE:


Production revenue receivable balances of $65,000 in aggregate represent amounts due the Company from a portion of the sale price of a 25% working interest in East Slopes Project in Kern County, California that was acquired through the default of certain original working interest partners in the project.  Production revenue receivable balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Production revenue receivable – current

$

65,000

 

$

120,000

Production revenue receivable – non-current

 

-

 

 

35,000

 

$

65,000

 

$

155,000



NOTE 7DEFERRED FINANCING COSTS:


Deferred financing costs at November 30, 2015 and February 28, 2015 relate to the original and the amended credit facility with Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to in these notes to the financial statements as “Maximilian”), are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Deferred financing costs – loan fees

$

160,795 

 

$

151,139 

Deferred financing costs – loan commissions

 

630,662 

 

 

630,662 

Deferred financing costs – fair value of warrants

 

530,488 

 

 

530,488 

Deferred financing costs – fair value of common stock

 

419,832 

 

 

419,832 

 

 

1,741,777 

 

 

1,732,121 

Accumulated amortization

 

(993,178)

 

 

(673,370)

 

$

748,599 

 

$

1,058,751 




8






The Company recognized amortization expense of $319,808 for the nine months ended November 30, 2015.



NOTE 8 NOTE RECEIVABLE:


Note receivable balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Note receivable – current

$

642,540

 

$

1,320,944

Note receivable – non-current

 

3,738,296

 

 

3,429,056

 

$

4,380,836

 

$

4,750,000


In connection with entering into the Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, (See Note 11 – Short-Term and Long-Term Borrowings), the Company concurrently entered into a Third Amendment to Loan and Security Agreement with App Energy (the “App Amendment”), which amended the Company’s loan agreement with App Energy in which the Company, as lender, lends to App Energy, as borrower, a portion of the advances it receives pursuant to its loan agreement with Maximilian.  The App Amendment provides for a reduction in interest rate from 19.2% to 17.0% and a reduction in monthly payments to $37,500 for principal payments to be made by App Energy to the Company for the same payment cycles as the reduced payment to be made by the Company under the Maximilian Amendment.  The reduction in monthly payments by App Energy will allow App Energy to fund its share of drilling and completing additional wells in Kentucky with the Company.  As consideration for the reduction in the monthly payment amount, App Energy agreed that certain amounts will be treated as additional advances under the App Energy loan agreement, and that it would fund a portion of the Company’s drilling and development expenses with respect to two wells.  App Energy also agreed to grant to Maximilian an overriding royalty interest on the same terms as the overriding royalty interest agreed to by the Company.



NOTE 9 ACCOUNTS PAYABLE:


On March 1, 2009, the Company became the operator for its East Slopes Project.  Additionally, the Company at that time assumed certain original partners’ default liability of approximately $1.5 million representing a 25% working interest in the drilling and completion costs associated with the East Slopes Project four earning well program.  The Company subsequently sold the same 25% working interest on June 11, 2009.  Of the $1.5 million default, $244,849 remains unpaid and is included in the November 30, 2015 accounts payable balance.



NOTE 10ACCOUNTS PAYABLE- RELATED PARTIES:


The November 30, 2015 and February 28, 2015 accounts payable – related parties balances were comprised primarily of deferred salaries of the Company’s Executive Officers and certain employees; deferred directors’ fees; expense reimbursements; and interest to the Company’s President and Chief Executive Officer on the 12% Subordinated Notes further described in Note 11 – Short-Term and Long-Term Borrowings below.  Payment of these items has been deferred until the Company’s cash flow situation improves.



NOTE 11 SHORT-TERM AND LONG-TERM BORROWINGS:


Note Payable – Related Party


As of November 30, 2015 and February 28, 2015, the Company’s President and Chief Executive Officer had loaned the Company $250,100 in aggregate that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; extension fees on third party loans; and a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.





9






Line of Credit


The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $28,770 for the nine months ended November 30, 2015.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.  At November 30, 2015 the Line of credit had an outstanding balance of $853,136.


Long-term Borrowings


12% Subordinated Notes


The Company’s 12% Subordinated Notes (“the Notes”) issued pursuant to a March 2010 private placement (of which $250,000 was from a related party) accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, the Company and 12 of the 13 note holders agreed to extend the maturity date of the Notes from January 29, 2015 for an additional two years.  The note principal is payable in full at the amended maturity date of the Notes, which is January 29, 2017.  Should the Board of Directors, on the amended maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2016.  The Notes consist of the following:


 

November 30, 2015

 

February 28, 2015

12% Subordinated Notes

$

315,000

 

$

315,000

12% Subordinated Notes – related party

 

250,000

 

 

250,000

 

$

565,000

 

$

565,000


Maximilian Credit Facility


On October 31, 2012, the Company entered into a loan agreement with Maximilian, which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and natural gas leases in Kern County, California.  The relative fair value of this 10% working interest amounting to $515,638 was recognized as a discount to debt and is being amortized over the original term of the loan.  Amortization expense was $100,896 for the nine months ended November 30, 2015.  Unamortized debt discount was $103,168 at November 30, 2015.


In 2012, the Company also issued 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the loan.  As of November 30, 2015, 316,617 of these warrants remain unexercised and outstanding.


Maximilian Credit Facility - Amended and Restated Loan Agreement


In connection with the Company’s acquisition of a working interest from App Energy in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.  The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on the Company’s leases in Kern County, California.  The amended loan agreement also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and natural gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App Energy, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App Energy on August 28, 2013 (See Note 8 – Note Receivable).




10






The amended loan agreement contains customary covenants for loans of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by Maximilian, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.


As consideration for Maximilian facilitating the Company’s transactions with App Energy and entering into the amended loan agreement, the Company (a) issued to Maximilian approximately 6.1 million common shares, representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.  The warrants had an exercise price of $0.10; contained a cash exercise provision and were exercisable for a period of three years expiring on August 28, 2016; and contained an exercise blocker provision that prevents any exercise of the warrants if such exercise and related issuance of common stock would increase the Maximilian holdings of the Company’s common stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian a 50% net profits interest in the Company’s approximate 25% working interest, after the Company recovers its investment in the Kentucky acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.


On May 28, 2014 at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares, issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.


On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “First Amendment”) with Maximilian.  The Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment.  Additionally, Maximilian agreed to temporarily reduce the required monthly payment made by the Company until it had paid $1,000,000 less than principal payments required by the previous agreement.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.


The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the Company’s acquisition of 5,694,823 shares of its common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  The Company paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.


On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “Second Amendment”) with Maximilian.  The Second Amendment modified the calculation of the required monthly payment for a three-month period ending June 30, 2015.  As consideration for entering into the loan modification, the Company agreed to modify the exercise price of the warrants Maximilian currently holds from $0.10 to $0.04.  No other terms of the warrant agreement were changed.  The modification did not result to any accounting since these warrants were deemed to be investor warrants.


On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, (the “Third Amendment”).  Pursuant to the Third Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016.  The reduction in monthly payments allows for additional funds to be used by the Company in drilling and completing additional wells in Kentucky.  As consideration for the reduction in the monthly payment amount, the Company agreed that twenty percent (20%) of the amount by which the monthly payment was reduced would be added to the loan balance, and the portion of the monthly payment savings that constitutes savings in interest or commitment fees would be treated as an additional advance of principal under the loan agreement (the “Deemed Advances”).  The 20% fee is being recognized as additional interest expense.  The Company also agreed to grant to Maximilian an overriding royalty interest of 1.5% of its working interest in four wells in Kentucky.  As part of the Maximilian Amendment, the Company also agreed to extend the expiration date of the warrants held by Maximilian to purchase up to 6,550,281 shares of common stock of the Company to August 28, 2018.  The Company determined that the accounting of the loan modification was not substantial.  Likewise, the Company determined that the modification of the warrant term did not result in any accounting since these warrants were deemed to be investor warrants.




11






With the cooperation of Maximilian, the Company is currently working with an investment banking firm to assist in securing refinancing of its debt with Maximilian, since the long-term commitment needed to develop the Kentucky and California projects no longer fits the Maximilian business model.  A waiver was granted by Maximilian for the January 1, 2016 payment that was not made by the Company to Maximilian.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices.


Current debt balances at November 30, 2015, and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Maximilian note

$

3,419,074 

 

$

4,823,325 

Maximilian note - discount

 

(103,168)

 

 

(132,114)

 

$

3,315,906 

 

$

4,691,211 


Non-current debt balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Maximilian note

$

10,138,706 

 

$

8,663,458 

Maximilian note - discount

 

 

 

(71,951)

 

$

10,138,706 

 

$

8,591,507 



NOTE 12 — STOCKHOLDERS’ DEFICIT:


Series A Convertible Preferred Stock


The Company has designated 2,400,000 shares of the 10,000,000 preferred shares as Series A Convertible Preferred Stock (“Series A Preferred”), with a $0.001 par value.  At November 30, 2015, there were 724,565 shares issued and outstanding, that had not been converted into our common stock.  As of November 30, 2015, there are 43 accredited investors who have converted 675,200 Series A Preferred shares into 2,025,600 shares of Daybreak common stock.  The conversions of Series A Preferred that have occurred since the Series A Preferred was first issued in July 2006 is set forth in the table below.



Fiscal Period

 

Shares of Series

A Preferred

Converted to

Common Stock

 

Shares of

Common Stock

Issued from

Conversion

 

Number of

Accredited

Investors

Year Ended February 29, 2008

 

102,300

 

306,900

 

10

Year Ended February 28, 2009

 

237,000

 

711,000

 

12

Year Ended February 28, 2010

 

51,900

 

155,700

 

4

Year Ended February 28, 2011

 

102,000

 

306,000

 

4

Year Ended February 29, 2012

 

-

 

-

 

-

Year Ended February 28, 2013

 

18,000

 

54,000

 

2

Year Ended February 28, 2014

 

151,000

 

453,000

 

9

Year Ended February 28, 2015

 

3,000

 

9,000

 

1

Nine Months Ended November 30, 2015

 

10,000

 

30,000

 

1

Totals

 

675,200

 

2,025,600

 

43






12






Holders of Series A Preferred shall be paid dividends, in the amount of 6% of the original purchase price per annum. Dividends are cumulative from the date of the final closing of the private placement, whether or not in any dividend period or periods we have assets legally available for the payment of such dividends.  As of November 30, 2015, no dividends have been paid.  Dividends earned since issuance for each fiscal year and the nine months ended November 30, 2015 are set forth in the table below:


Fiscal Period

 

Shareholders at Period End

 

Earned Dividends

Year Ended February 28, 2007

 

100

 

$

155,311

Year Ended February 29, 2008

 

90

 

 

242,126

Year Ended February 28, 2009

 

78

 

 

209,973

Year Ended February 28, 2010

 

74

 

 

189,973

Year Ended February 28, 2011

 

70

 

 

173,707

Year Ended February 29, 2012

 

70

 

 

163,624

Year Ended February 28, 2013

 

68

 

 

161,906

Year Ended February 28, 2014

 

59

 

 

151,323

Year Ended February 28, 2015

 

58

 

 

132,634

Nine Months Ended November 30, 2015

 

57

 

 

98,410

Total Accumulated Dividends

 

 

 

$

1,678,987


Common Stock


The Company is authorized to issue up to 200,000,000 shares of $0.001 par value common stock of which 51,487,373 shares were issued and outstanding as of November 30, 2015.  In comparison, at February 28, 2015, a total of 51,457,373 shares were issued and outstanding.  The increase of 30,000 shares was attributable as shown below:


 

Common Stock

Balance

 

Par Value

Common stock, Issued and Outstanding, February 28, 2015

51,457,373

 

 

 

Conversion of Series A Convertible Preferred Stock to Common Stock

30,000

 

$

30

Common stock, Issued and Outstanding, November 30, 2015

51,487,373

 

 

 



NOTE 13 — WARRANTS:


Warrants outstanding and exercisable as of November 30, 2015 are set forth in the table below:

 

 

Warrants

 

Exercise

Price

 

Remaining

Life

(Years)

 

Exercisable

Warrants

Remaining

12% Subordinated notes

 

1,190,000 

 

$0.14

 

1.17

 

980,000 

Warrants issued in 2012 for debt financing

 

2,435,517 

 

$0.044

 

1.92

 

316,617 

Warrants issued for Kentucky oil project

 

3,498,601 

 

$0.04

 

2.75

 

3,498,601 

Warrants issued for Kentucky debt financing

 

2,623,951 

 

$0.04

 

2.75

 

2,623,951 

Warrants issued for Kentucky debt financing

 

309,503 

 

$0.214

 

2.75

 

309,503 

Warrants issued in share-for-warrant exchange

 

427,729 

 

$0.04

 

2.75

 

427,729 

 

 

10,485,301 

 

 

 

 

 

8,156,401 


There were 150,000 warrants issued in 2010 for services that expired during the nine months ended November 30, 2015.  During the nine months ended November 30, 2015 there were no warrants issued or exercised.  The remaining outstanding warrants as of November 30, 2015, have a weighted average exercise price of $0.06, a weighted average remaining life of 2.53 years, and an intrinsic value of -$0-.



NOTE 14 INCOME TAXES:


Reconciliation between actual tax expense (benefit) and income taxes computed by applying the U.S. federal income tax rate and state income tax rates to income from continuing operations before income taxes is set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Computed at U.S. and state statutory rates (40%)

$

(752,885)

 

$

(293,176)

Permanent differences

 

88,175 

 

 

142,925 

Changes in valuation allowance

 

664,710 

 

 

150,251 

 

$

 

$




13






Tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred liabilities are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Deferred tax assets:

 

 

 

 

 

Net operating loss carryforwards

$

9,913,956 

 

$

9,188,905 

Oil and natural gas properties

 

(1,420,887)

 

 

(1,436,249)

Stock based compensation

 

88,723 

 

 

88,723 

Other

 

(178,602)

 

 

(102,899)

Less valuation allowance

 

(8,403,190)

 

 

(7,738,480)

 

$

 

$


At November 30, 2015, Daybreak had estimated net operating loss (“NOL”) carryforwards for federal and state income tax purposes of approximately $24,784,890 which will begin to expire, if unused, beginning in 2024.  The valuation allowance increased $664,710 for the nine months ended November 30, 2015 and increased by $150,251 for the year ended February 28, 2015. Section 382 of the Internal Revenue Code places annual limitations on the Company’s NOL carryforward.


The above estimates are based on management’s decisions concerning elections which could change the relationship between net income and taxable income.  Management decisions are made annually and could cause estimates to vary significantly.



NOTE 15 — COMMITMENTS AND CONTINGENCIES:


Various lawsuits, claims and other contingencies arise in the ordinary course of the Company’s business activities.  While the ultimate outcome of any future contingency is not determinable at this time, management believes that any liability or loss resulting therefrom will not materially affect the financial position, results of operations or cash flows of the Company.


The Company, as an owner or lessee and operator of oil and natural gas properties, is subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment.  These laws and regulations may, among other things, impose liability on the lessee under an oil and natural gas lease for the cost of pollution clean-up resulting from operations and subject the lessee to liability for pollution damages.  In some instances, the Company may be directed to suspend or cease operations in the affected area.  The Company maintains insurance coverage that is customary in the industry, although the Company is not fully insured against all environmental risks.


The Company is not aware of any environmental claims existing as of November 30, 2015.  There can be no assurance, however, that current regulatory requirements will not change or that past non-compliance with environmental issues will not be discovered on the Company’s oil and natural gas properties.










14







ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


The following discussion is management’s assessment of the current and historical financial and operating results of the Company and of our financial condition.  It is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our unaudited financial statements and notes thereto included elsewhere in this Quarterly Report on Form 10-Q for the nine months ended November 30, 2015 and in our Annual Report on Form 10-K for the year ended February 28, 2015.  References to “Daybreak”, the “Company”, “we”, “us” or “our” mean Daybreak Oil and Gas, Inc.


Cautionary Statement Regarding Forward-Looking Statements


Certain statements contained in our Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) are intended to be covered by the safe harbor provided for under Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act.


All statements other than statements of historical fact contained in this MD&A report are inherently uncertain and are forward-looking statements.  Statements that relate to results or developments that we anticipate will or may occur in the future are not statements of historical fact.  Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “predict,” “project,” “will” and similar expressions identify forward-looking statements.  Examples of forward-looking statements include, without limitation, statements about the following:

·

Our future operating results;

·

Our future capital expenditures;

·

Our future financing;

·

Our expansion and growth of operations; and

·

Our future investments in and acquisitions of oil and natural gas properties.


We have based these forward-looking statements on assumptions and analyses made in light of our experience and our perception of historical trends, current conditions, and expected future developments.  However, you should be aware that these forward-looking statements are only our predictions and we cannot guarantee any such outcomes.  Future events and actual results may differ materially from the results set forth in or implied in the forward-looking statements.  Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:

·

General economic and business conditions;

·

Exposure to market risks in our financial instruments;

·

Fluctuations in worldwide prices and demand for oil and natural gas;

·

Our ability to find, acquire and develop oil and natural gas properties;

·

Fluctuations in the levels of our oil and natural gas exploration and development activities;

·

Risks associated with oil and natural gas exploration and development activities;

·

Competition for raw materials and customers in the oil and natural gas industry;

·

Technological changes and developments in the oil and natural gas industry;

·

Legislative and regulatory uncertainties, including proposed changes to federal tax law and climate change legislation, regulation of hydraulic fracturing and potential environmental liabilities;

·

Our ability to continue as a going concern;

·

Our ability to secure financing under any commitments as well as additional capital to fund operations; and

·

Other factors discussed elsewhere in our Form 10-K for the year ended February 28, 2015; in this Form 10-Q; in our other public filings and press releases; and discussions with Company management.


Our reserve estimates are determined through a subjective process and are subject to revision.


Should one or more of the risks or uncertainties described above or elsewhere in our Form 10-K for the year ended February 28, 2015 and in this Form 10-Q occur, or should any underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.  We specifically undertake no obligation to publicly update or revise any information contained in any forward-looking statement or any forward-looking statement in its entirety, whether as a result of new information, future events, or otherwise, except as required by law.


All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.



15






Introduction and Overview


We are an independent oil and natural gas exploration, development and production company.  Our basic business model is to increase shareholder value by finding and developing oil and natural gas reserves through exploration and development activities, and selling the production from those reserves at a profit.  To be successful, we must, over time, be able to find oil and natural gas reserves and then sell the resulting production at a price that is sufficient to cover our finding costs, operating expenses, administrative costs and interest expense, plus offer us a return on our capital investment.  A secondary means of generating returns can include the sale of either producing or non-producing lease properties.


Our longer-term success depends on, among many other factors, the acquisition and drilling of commercial grade oil and natural gas properties and on the prevailing sales prices for oil and natural gas along with associated operating expenses.  The volatile nature of the energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices, such as we are now experiencing, would have a material adverse effect on our results of operations and financial condition.


Our operations are focused on identifying and evaluating prospective oil and natural gas properties and funding projects that we believe have the potential to produce oil or natural gas in commercial quantities.  We conduct all of our drilling, exploration and production activities in the United States, and all of our revenues are derived from sales to customers within the United States.  Currently, we are in the process of developing two multi-well oilfield projects; one in Lawrence County, Kentucky and the other in Kern County, California.


In the current fiscal year, we will continue to seek additional financing for our planned exploration and development activities in both Kentucky and California.  The Company has engaged an investment banking firm to assist in securing refinancing of its debt under more favorable terms and implement its development plans in California and Kentucky.  We plan to obtain financing through various methods, including issuing debt securities, equity securities, or bank debt, or combinations of these instruments, which could result in dilution to existing security holders and increased debt and leverage.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.  Sales of interests in our assets may be another source of cash flow.


Our management cannot provide any assurances that Daybreak will ever operate profitably.  We have not been able to generate sustained positive earnings on a Company-wide basis.  As a small company, we are more susceptible to the numerous business, investment and industry risks that have been described in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended February 28, 2015 and in Part III, Item 1A. Risk Factors of this 10-Q Report.  Throughout this Quarterly Report on Form 10-Q, oil is shown in barrels (“Bbls”); natural gas is shown in thousands of cubic feet (“Mcf”) unless otherwise specified, and hydrocarbon totals are expressed in barrels of oil equivalent (“BOE”).


Below is summary of our oil and natural gas projects in Kentucky and California.


Lawrence County, Kentucky (Twin Bottoms Field)


The Twin Bottoms Field, comprising approximately 7,300 acres in two large contiguous blocks, is located in the Appalachian Basin of eastern Kentucky.  Log data from existing vertical natural gas wells in the field indicate the existence of proved oil reserves in the Berea sandstone, located at approximately 2,000 feet.  The lateral leg of each well is between 2,000 feet and 4,500 feet in length.  We have an approximate 25% working interest and an approximate net revenue interest (“NRI”) of 21.9% in all horizontal oil wells in this project.  The oil produced from our acreage in Kentucky is light crude oil measuring between 42° and 44° API gravity.  We are not the Operator of the Twin Bottoms Field project; instead we rely on the experience of the current Operator and its knowledge of this Field.


At November 30, 2015, we had 14 producing horizontal oil wells in the Twin Bottoms Field.  Our first well, the Grove H-1 was put on production in October 2013.  During the year ended February 28, 2014, three additional oil wells, the Grove #H-3, Grove #H-4 and Grove #H-5, were put on production.  Nine additional horizontal oil wells, the Dillon #H-6, Grove #H-7, Grove #H-8, Grove #H-9, Grove #H-10, Jackson #H-20, Lyons #H-23, Lyons #H-24 and the Dillon #H-22, were put on production during the year ended February 28, 2015.  The App Energy #H-33 well was drilled in October 2015 to a measured depth of 5,251 feet and encountered 3,913 feet of oil pay in the Berea Sandstone.  Our average working interest and NRI in these 14 producing horizontal oil wells is 22.6% and 19.7%, respectively.


In August 2015, we drilled the vertical leg portion of the Murray #H-34 well.  The well was logged and data was collected for use in the drilling of the App Energy #H-33 well.  The Company paid 12.5% of the drilling and completion cost for a 25% working interest in the App Energy H-33 and Murray #H-34 wells as part of the App Amendment.  The horizontal portion of the Murray #H-34 well will be drilled at a later date.



16






Kentucky Drilling Plans


Selected wells may be drilled from time to time to maintain production and leases, however; implementation of our full development plan will not begin until there is a sustained improvement in crude oil prices and additional financing is put in place.  We do not plan to make any capital investments in the Twin Bottoms Field project area during the remainder of the 2015-2016 fiscal year.


Kern County, California (East Slopes Project)


The East Slopes Project is located in the southeastern part of the San Joaquin Basin near Bakersfield, California.  Drilling targets are porous and permeable sandstone reservoirs which exist at depths of 1,200 feet to 4,500 feet.  Since January 2009, we have participated in the drilling of 25 wells in this project.  We have been the Operator at the East Slopes Project since March 2009.


Our 20 oil wells in the East Slopes Project produce from five reservoirs at our Sunday, Bear, Black, Ball and Dyer Creek locations.  The Sunday property has six producing wells, while the Bear property has nine producing wells.  The Black property is the smallest of all currently producing reservoirs, and currently has two producing wells at this property.  The Ball property also has two producing wells while the Dyer Creek property has one producing well.  Our average working interest and NRI in these 20 producing oil wells is 36.6% and 28.5%, respectively.  There are several other similar prospects on trend with the Bear, Black and Dyer Creek reservoirs exhibiting the same seismic characteristics.  Some of these prospects, if successful, would utilize the Company’s existing production facilities.  In addition to the current field development, there are several other exploratory prospects that have been identified from the seismic data, which we plan to drill in the future.


Sunday Central Processing and Storage Facility


The oil produced from our acreage in California is considered heavy oil.  The oil ranges from 14° to 16° API (American Petroleum Institute) gravity.  All of the oil from our five producing properties is processed, stored and sold from the Sunday central processing and storage facility.  The oil must be heated to separate and remove water to prepare it to be sold.  We constructed these facilities during the summer and fall of 2009 and at the same time established electrical service for our field by constructing three miles of power lines.  In 2013, we completed an upgrade to this facility including the addition of a second oil storage tank to handle the additional oil production from the wells drilled in 2013.


By utilizing the Sunday centralized production facility our average operating costs have been reduced from over $40 per barrel in 2009 to a monthly average of approximately $12 per barrel of oil for the nine months ended November 30, 2015.  With this centralized facility and having permanent electrical power available, we are ensuring that our operating expenses are kept to a minimum.


Exploration Properties


Bull Run Prospect


This prospect is located in the southern portion of our acreage position.  The drilling targets are the Etchegoin and Santa Margarita sands located between 800 and 1,200 feet deep.  Utilizing the data received from a previously drilled well that was not commercially successful, we expect to drill another exploratory well on this prospect in the future.  Future Bull Run wells will require a pilot steam flood and production facilities.  We estimate that the Bull Run prospect is 70 acres in size.  We have a 37.5% working interest in this prospect.


Sherman Prospect


This prospect is also located in the southern portion of our acreage position.  The drilling targets are the Olcese and Etchegoin sands between 1,000 and 2,000 feet deep.  We estimate that the Sherman Prospect is 100 acres in size.  The Company is currently seeking an extension of the leases in this prospect which expire in May 2016.  We have a 37.5% working interest in this prospect.


Tobias Prospect


This prospect is also located in the central portion of our acreage position.  The drilling targets are the Vedder and Eocene sands between 2,000 and 4,500 feet deep.  This prospect be drilled in the future.  We estimate that the Tobias prospect is 60 acres in size.  We have a 37.5% working interest in this prospect.



17






California Drilling Plans


Future drilling plans include a combination of both exploratory drilling and development well drilling.  Planned drilling activity and implementation of our full development plan will not begin until there is a sustained improvement in crude oil prices and additional financing is put in place.  We do not plan to make any capital investments in the East Slopes Project during the rest of the 2015-2016 fiscal year.

 

Encumbrances


The Company’s debt obligations, pursuant to a loan agreement entered into by and between Maximilian Resources LLC, a Delaware limited liability company and successor by assignment to Maximilian Investors LLC (either party, as appropriate, is referred to “Maximilian”), as lender, and the Company are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek properties.  For further information on the loan agreement refer to the discussion under the caption “Non-current Borrowings” in this MD&A.


Results of Operations – Nine Months Ended November 30, 2015 compared to the Nine Months Ended November 30, 2014


Hydrocarbon Prices


The price we receive for oil sales in both Kentucky and California is based on prices quoted on the New York Mercantile Exchange (“NYMEX”) for spot West Texas Intermediate (“WTI”) Cushing, Oklahoma delivery contracts, less deductions that vary by grade of crude oil sold and transportation costs.  The price we receive for natural gas sales in Kentucky per Mcf is based on the Columbia Gas Transmission Corp. Appalachia Index (“TCO Appalachia”) whereby we will receive 76% of the TCO Appalachia price per dekatherm (DTH) less $0.25 compression cost for each Mcf of natural gas delivered.  We do not have any natural gas revenues in California.


Since June 2014, there has been a significant decline in the WTI price of crude oil and subsequently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties as shown in the table below.


 

 

June 2014

 

November 2015

 

Percentage Decline

Monthly average WTI crude oil price

 

$

105.79

 

$

42.39

 

59.9%

Monthly average realized crude oil sales price (Bbl)

 

$

101.32

 

$

36.66

 

63.8%


Kentucky Oil Prices


For the nine months ended November 30, 2015, our average realized oil sale price was $49.38 in comparison to the average WTI price of $49.94 representing a discount of $0.56 per barrel or 1.1% lower than the average WTI price.  In comparison, for the nine months ended November 30, 2014, the average WTI price was $96.04 and our average realized sale price was $95.48 representing a discount of $0.56 per barrel or 0.6% lower than the average WTI price.


Kentucky Natural Gas Prices


For the nine months ended November 30, 2015, our average realized natural gas sale price was $1.62 per Mcf (thousand cubic feet) in comparison to the average Henry Hub price of $2.64 per million BTU representing a discount of $1.02 per Mcf or 38.6% lower than the average Henry Hub price.  In comparison, for the nine months ended November 30, 2014, the average realized sale price was $3.01 per Mcf in comparison to the average Henry Hub price of $4.28 per million BTU representing a discount of $1.27 or 29.7% lower than the average Henry Hub price.


California Oil Prices


For the nine months ended November 30, 2015, the average WTI price was $49.94 and our average realized oil sale price was $41.89, representing a discount of $8.05 per barrel or 16.1% lower than the average WTI price.  In comparison, for the nine months ended November 30, 2014, the average WTI price was $96.04 and our average realized sale price was $89.10 representing a discount of $6.94 per barrel or 7.2% lower than the average WTI price.  Historically, the sale price we receive for California heavy oil has been less than the quoted WTI price because of the lower API gravity of our California oil in comparison to WTI oil API gravity.



18






Total Oil and Natural Gas Revenue and Production


Our revenues are derived entirely from the sale of our share of oil production in Kentucky and California and natural gas sales in Kentucky. Oil and natural gas revenues for the nine months ended November 30, 2015 in aggregate decreased $1,430,925 or 56.8%, to $1,087,450 in comparison to revenues of $2,518,375 for the nine months ended November 30, 2014.  Oil and natural gas sales volume decreased 2,520 BOE (barrels of oil equivalent) or 8.6% to 26,528 (BOE) in comparison to 29,048 (BOE) for the nine months ended November 30, 2014.  The decrease in volume was due to the natural decline in oil producing reservoir pressure.  Our average realized sale price on a BOE basis for the nine months ended November 30, 2015 was $40.99 in comparison to $86.75 for the nine months ended November 30, 2014, representing a decline of $45.76 or 52.8% per barrel.


Kentucky Oil Revenue and Production


Production in Kentucky is from horizontal oil wells in consolidated shale sands that are characterized by large initial production volumes that decline quite rapidly to a much lower and more stable long-term production volume.  Fluctuations in revenue are closely linked to both production volumes and crude oil prices.  Our first oil sales in Kentucky occurred in October 2013.  Oil revenue in Kentucky for the nine months ended November 30, 2015 decreased $754,841 or 55.7% to $601,339 in comparison to revenue of $1,356,180 for the nine months ended November 30, 2014.  The average realized sale price of a barrel of oil for the nine months ended November 30, 2015 was $49.38 in comparison to $95.48 for the nine months ended November 30, 2014.  The decrease of $46.11 or 48.3% in the average sale price of a barrel of oil was responsible for 86.8% of the decline in Kentucky oil revenue for the nine months ended November 30, 2015.


Our net sales volume in the nine months ended November 30, 2015 was 12,179 barrels of oil in comparison to 14,221 barrels sold during the nine months ended November 30, 2014.  This decrease in oil sales volume of 2,042 barrels or 14.4% was responsible for 13.2% of the decline in Kentucky oil revenue for the nine months ended November 30, 2015.


The API gravity of our produced oil in Kentucky ranges between 42° API and 44° API.  Production for the nine months ended November 30, 2015 was from 14 wells resulting in 3,274 well days of production in comparison to 1,709 well days from 10 horizontal oil wells during the nine months ended November 30, 2014.


Kentucky Natural Gas Revenue and Production


Natural gas production is a by-product from our horizontal oil wells and the volume varies on a well-to-well basis.   Our first natural gas sales in Kentucky also occurred in October 2013.  Natural gas revenue for the nine months ended November 30, 2015 decreased $4,583 to $34,752 in comparison to revenue of $39,335 for the nine months ended November 30, 2014.  The average realized sale price per Mcf for the nine months ended November 30, 2015 was $1.62 in comparison to $3.01 for the nine months ended November 30, 2014.


Our net sales volume in the nine months ended November 30, 2015 was 21,443 Mcf or 3,574 BOE in comparison to 13,350 Mcf or 2,225 BOE during the nine months ended November 30, 2014.  The increase of 8,093 MCF or 1,349 BOE representing a 60.6% increase was due to infrastructure improvements that had previously inhibited natural gas production from existing wells.


California Revenue and Production


Production in California is from vertical oil wells that historically produce at relatively stable levels over time.  Fluctuations in revenue are generally more dependent on the price of crude oil and the timing of oil sales rather than oil production volumes.  Oil revenue in California for the nine months ended November 30, 2015 decreased $671,501 or 59.8% to $451,359 in comparison to revenue of $1,122,860 for the nine months ended November 30, 2014.  The average realized sale price of a barrel of oil for the nine months ended November 30, 2015 was $41.89 in comparison to $89.10 for the nine months ended November 30, 2014.  The decrease of $47.22 or 53.0% in the average realized sale price of a barrel of oil accounted for 88.6% of the decrease in California oil revenue for the nine months ended November 30, 2015.


Our net sales volume in the nine months ended November 30, 2015 was 10,775 barrels of oil in comparison to 12,602 barrels sold during the nine months ended August 31, 2014.  This decrease in oil sales volume of 1,827 barrels or 14.5% accounted for 11.4% of the decrease in California oil revenue for the nine months ended November 30, 2015.  The decrease in volume was due to natural decline in the oil producing reservoirs.




19






The gravity of our produced oil in California ranges between 14° API and 16° API.  Production for the nine months ended November 30, 2015 was from 20 wells resulting in 5,410 well days of production in comparison to 5,482 of production from 20 wells for the nine months ended November 30, 2014.


Oil and natural gas revenues for the nine months ended November 30, 2015 and 2014 are set forth in the table below:


 

 

Nine Months Ended

November 30, 2015

 

Nine Months Ended

November 30, 2014

 

 

Revenue

 

Percentage

 

Revenue

 

Percentage

Kentucky – Twin Bottoms Field (oil)  

 

$

601,339

 

55.3%

 

$

1,356,180

 

53.8%

Kentucky – Twin Bottoms Field (natural gas)  

 

 

34,752

 

3.2%

 

 

39,335

 

1.6%

California – East Slopes Project (oil)

 

 

451,359

 

41.5%

 

 

1,122,860

 

44.6%

Total oil and natural gas revenues*

 

$

1,087,450

 

100.0%

 

$

2,518,375

 

100.0%


*Our average realized sale price on a BOE basis for the nine months ended November 30, 2015 was $40.99 in comparison to $86.75 for the nine months ended November 30, 2014, representing a decline of $45.76 or 52.8% per barrel.


Operating Expenses.  Total operating expenses for the nine months ended November 30, 2015 decreased by $127,503 or 8.2% to $1,420,624 in comparison to $1,548,127 for the nine months ended November 30, 2014.


Operating expenses for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Nine Months Ended

November 30, 2015

 

Nine Months Ended

November 30, 2014

 

 

Expenses

 

Percentage

 

BOE

Basis

 

Expenses

 

Percentage

 

BOE

Basis

Production expenses

 

$

208,243

 

14.7%

 

 

 

 

$

251,625

 

16.3%

 

 

 

Exploration and drilling expenses

 

 

29,823

 

2.1%

 

 

 

 

 

20,172

 

1.3%

 

 

 

Depreciation, Depletion, Amortization, and Impairment (“DD&A”)

 

 

399,698

 

28.1%

 

 

 

 

 

426,366

 

27.5%

 

 

 

General and Administrative (“G&A”) expenses

 

 

782,860

 

55.1%

 

 

 

 

 

849,964

 

54.9%

 

 

 

Total operating expenses

 

$

1,420,624

 

100.0%

 

$

53.55

 

$

1,548,127

 

100.0%

 

$

53.33


Production expenses include expenses associated with the production of oil and natural gas.  These expenses include pumper salaries, electricity, road maintenance, control of well insurance, property taxes and well workover expenses; and, relate directly to the number of wells that are in production.  For the nine months ended November 30, 2015, these expenses decreased by $43,382 or 17.2% to $208,243 in comparison to $251,625 for the nine months ended November 30, 2014.  For the nine months ended November 30, 2015 we had 20 wells on production in California and 14 wells on production in Kentucky in comparison to 20 wells in California and 10 wells in Kentucky for the nine months ended November 30, 2014.  Production expenses represented 14.7% of total operating expenses.


Production expenses in Kentucky and California for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Nine Months Ended

November 30, 2015

 

Nine Months Ended

November 30, 2014

 

 

Expenses

 

Percentage

 

Expenses

 

Percentage

Kentucky – Twin Bottoms Field  

 

$

86,928

 

41.7%

 

$

106,633

 

42.4%

California – East Slopes Project

 

 

121,315

 

58.3%

 

 

144,992

 

57.6%

Total production expenses

 

$

208,243

 

100.0%

 

$

251,625

 

100.0%


Production expenses on a BOE basis in Kentucky and California for the nine months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Nine Months Ended

 

 

November 30, 2015

 

November 30, 2014

Kentucky – Twin Bottoms Field (BOE)  

 

$

5.52

 

$

6.39

California – East Slopes Project (BOE)

 

$

11.26

 

$

11.63

Aggregate production expenses (BOE)

 

$

7.85

 

$

8.66




20






Exploration and drilling expenses include geological and geophysical (“G&G”) expenses as well as leasehold maintenance and dry hole expenses.  These expenses increased $9,651 or 47.8% to $29,823 for the nine months ended November 30, 2015 in comparison to $20,172 the nine months ended November 30, 2014 primarily due to additional G&G work in Kentucky.  Exploration and drilling expenses represented 2.1% of total operating expenses.


DD&A expenses relate to equipment, proven reserves and property costs, along with impairment and is another component of operating expenses.  For the nine months ended November 30, 2015, DD&A expenses decreased $26,668 or 6.3% to $399,698 in comparison to $426,366 for the nine months ended November 30, 2014.  The decrease in DD&A is directly related to the level of our hydrocarbon production in both Kentucky and California offset by additional impairment in California of $34,744.  On a BOE basis, DD&A and impairment represented $15.07 and $14.68 per barrel for the nine months ended November 30, 2015 and 2014, respectively.  DD&A expenses represented 28.1% of total operating expenses.


G&A expenses include the salaries of six full-time employees, including management.  Other items included in our G&A expenses are legal and accounting expenses, director fees, stock compensation, investor relations fees, travel expenses, insurance, Sarbanes-Oxley (“SOX”) compliance expenses and other administrative expenses necessary for an operator of oil and natural gas properties as well as for running a public company.  For the nine months ended November 30, 2015, G&A expenses decreased $67,104 or 7.9% to $782,860 in comparison to $849,964 for the nine months ended November 30, 2014.  We received, as Operator in California, administrative overhead reimbursement of $39,965 during the nine months ended November 30, 2015 for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A expenses represented 55.1% of total operating expenses.


Interest income for the nine months ended November 30, 2015 decreased $70,078 or 8.4% to $763,700 in comparison to $833,778 for the nine months ended November 30, 2014 due to reduced interest rates and modification of the Note receivable from App Energy. For further discussion on the App Energy Note refer to the discussion of the App Loan Agreement under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.


Interest expense for the nine months ended November 30, 2015 increased $231,151 or 11.1% to $2,312,741 in comparison to $2,081,590 for the nine months ended November 30, 2014.  The increase in interest expense is directly related to the modified loan payment terms on our credit facility with Maximilian.  The credit facility activity is discussed further in the discussion of the Maximilian Credit Facility – Amended and Restated Loan Agreement in the  MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.


Results of Operations – Three Months Ended November 30, 2015 compared to the Three Months Ended November 30, 2014


Kentucky Oil Prices


For the three months ended November 30, 2015, our average realized oil sale price was $43.66 in comparison to the average WTI price of $44.70 representing a discount of $1.04 per barrel or 2.3% from the average WTI price.  In comparison, for the three months ended November 30, 2014 the average WTI price was $84.47 and our average realized sale price was $84.11, representing a discount of $0.36 per barrel or 0.4% lower than the average WTI prices.


Kentucky Natural Gas Prices


For the three months ended November 30, 2015, our average realized natural gas sale price was $1.33 per Mcf in comparison to the average Henry Hub price of $2.36 per million BTU representing a discount of $1.03 per Mcf or 43.5% lower than the average Henry Hub price.  In comparison, for the three months ended November 30, 2014, the average realized sale price was $3.15 per Mcf while the average Henry Hub price was $3.94 per million BTU representing a discount of $0.79 or 20.0% lower than the average Henry Hub price.


California Oil Prices


For the three months ended November 30, 2015, the average WTI price was $44.70 and our average realized oil sale price was $35.88 representing a discount of $8.82 per barrel or 19.7% lower than the average WTI price.  In comparison, for the three months ended November 30, 2014, the average WTI price was $84.47 and our average realized sale price was $75.80, representing a discount of $8.67 per barrel or 10.3% lower than the average WTI price.




21






Total Oil and Natural Gas Revenue and Production


Oil and natural gas revenues for the three months ended November 30, 2015 in aggregate decreased $387,318 or 58.4%, to $276,332 in comparison to revenues of $663,650 for the three months ended November 30, 2014.  Oil and natural gas sales volume decreased 1,272 BOE (barrels of oil equivalent) or 13.9% to 7,891 (BOE) in comparison to 9,163 (BOE) for the three months ended November 30, 2014.  Our average realized sale price on a BOE basis for the three months ended November 30, 2015 was $35.02 in comparison to $72.43 for the three months ended November 30, 2014, representing a decline of $37.41 or 51.6% per barrel.


Kentucky Oil Revenue and Production


Oil revenue in Kentucky for the three months ended November 30, 2015 decreased $197,255 or 59.0% to $136,901 in comparison to revenue of $334,156 for the three months ended November 30, 2014.  The average realized sale price of a barrel of oil for the three months ended November 30, 2015 was $43.66 in comparison to $84.11 for the three months ended November 30, 2014.  The decrease of $40.46 or 48.1% in the average sale price of a barrel of oil accounted for 81.5% of the decline in Kentucky oil revenue for the three months ended November 30, 2015.


Our net sales volume for the three months ended November 30, 2015 was 3,136 barrels of oil in comparison to 3,991 barrels sold for the three months ended August 31, 2014.  This decrease in oil sales volume of 855 barrels or 21.4% accounted for 18.5% of the decline in Kentucky oil revenue for the three months ended November 30, 2015.


Production for the three months ended November 30, 2015 was from 14 wells resulting in 1,102 well days of production in comparison to 776 well days from 10 horizontal oil wells during for the three months ended November 30, 2014.


Kentucky Natural Gas Revenue and Production


Natural gas revenue for the three months ended November 30, 2015 decreased $11,858 to $8,948 in comparison to revenue of $20,806 for the three months ended November 30, 2014.  The average realized sale price per Mcf for the three months ended November 30, 2015 was $1.33 in comparison to $3.15 for the three months ended November 30, 2014.  Our net sales volume for the three months ended November 30, 2015 was 6,710 Mcf or 1,118 BOE in comparison to 6,599 Mcf or 1,100 BOE for the three months ended November 30, 2014.  The increase in natural gas volume of 112 or 19 BOE representing a 1.7% increase was due to infrastructure improvements that had previously inhibited natural gas production from existing wells.


California Revenue and Production


Oil revenue in California for the three months ended November 30, 2015 decreased $178,205 or 57.7% to $130,483 in comparison to revenue of $308,688 for the three months ended November 30, 2014.  The average realized sale price of a barrel of oil for the three months ended November 30, 2015 was $35.88 in comparison to $75.80 for the three months ended November 30, 2014.  The decrease of $39.92 or 52.7% in the average realized sale price of a barrel of oil accounted for 91.2% of the decrease in California oil revenue for the three months ended November 30, 2015.


Our net sales volume for the three months ended November 30, 2015 was 3,637 barrels of oil in comparison to 4,072 barrels sold for the three months ended November 30, 2014.  This decrease in oil sales volume of 435 barrels or 10.7% accounted for 8.8% of the decrease in revenue for the three months ended November 30, 2015.  Production for the three months ended November 30, 2015 was from 20 wells resulting in 1,748 well days of production in comparison to 1,816 of production from 20 wells for the three months ended November 30, 2014.


Oil and natural gas revenues for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Three Months Ended

November 30, 2015

 

Three Months Ended

November 30, 2014

 

 

Revenue

 

Percentage

 

Revenue

 

Percentage

Kentucky – Twin Bottoms Field (oil)  

 

$

136,901

 

49.6%

 

$

334,156

 

50.4%

Kentucky – Twin Bottoms Field (natural gas)  

 

 

8,948

 

3.2%

 

 

20,806

 

3.1%

California – East Slopes Project (oil)

 

 

130,483

 

47.2%

 

 

308,688

 

46.5%

Total oil and natural gas revenues*

 

$

276,332

 

100.0%

 

$

663,650

 

100.0%


*Our average realized sale price on a BOE basis for the three months ended November 30, 2015 was $35.02 in comparison to $72.43 for the three months ended November 30, 2014, representing a decline of $37.41 or 51.6% per barrel.




22






Operating Expenses.  Total operating expenses for the three months ended November 30, 2015 increased by $4,304 or 0.9% to $462,719 in comparison to $458,415 for the three months ended November 30, 2014.


Operating expenses for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Three Months Ended

November 30, 2015

 

Three Months Ended

November 30, 2014

 

 

Expenses

 

Percentage

 

BOE

Basis

 

Expenses

 

Percentage

 

BOE

Basis

Production expenses

 

$

62,637

 

13.5%

 

 

 

 

$

86,140

 

18.8%

 

 

 

Exploration and drilling expenses

 

 

9,756

 

2.1%

 

 

 

 

 

7,362

 

1.6%

 

 

 

Depreciation, Depletion, Amortization, and Impairment (“DD&A”)

 

 

141,969

 

30.7%

 

 

 

 

 

134,873

 

29.4%

 

 

 

General and Administrative (“G&A”) expenses

 

 

248,357

 

53.7%

 

 

 

 

 

230,040

 

50.2%

 

 

 

Total operating expenses

 

$

462,719

 

100.0%

 

$

58.64

 

$

458,415

 

100.0%

 

$

50.03


For the three months ended November 30, 2015, production expenses decreased by $23,503 or 27.3% to $62,637 in comparison to $86,140 for the three months ended November 30, 2014.  For the three months ended November 30, 2014 we had 20 wells on production in California and 14 wells on production in Kentucky in comparison to 20 wells in California and 10 wells in Kentucky for the three months ended November 30, 2014.  Production expenses represented 13.5% of total operating expenses for the three months ended November 30, 2015.


Production expenses in Kentucky and California for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Three Months Ended

November 30, 2015

 

Three Months Ended

November 30, 2014

 

 

Expenses

 

Percentage

 

Expenses

 

Percentage

Kentucky – Twin Bottoms Field

 

$

28,374

 

45.3%

 

$

31,482

 

36.5%

California – East Slopes Project

 

 

34,263

 

54.7%

 

 

54,658

 

63.5%

Total production expenses

 

$

62,637

 

100.0%

 

$

86,140

 

100.0%


Production expenses on a BOE basis in Kentucky and California for the three months ended November 30, 2015 and November 30, 2014 are set forth in the table below:


 

 

Three Months Ended

 

 

November 30, 2015

 

November 30, 2014

Kentucky – Twin Bottoms Field (BOE)

 

$

6.67

 

$

6.12

California – East Slopes Project (BOE)

 

$

9.42

 

$

13.42

Aggregate production expenses (BOE)

 

$

7.94

 

$

9.40


For the three months ended November 30, 2015, exploration and drilling expenses increased $2,394 or 32.5% to $9,756 in comparison to $7,362 for the three months ended November 30, 2014.  Exploration and drilling expenses represented 2.1% of total operating expenses for the three months ended November 30, 2015.


For the three months ended November 30, 2015, DD&A expenses increased $7,096 or 5.3% to $141,969 in comparison to $134,873 for the three months ended November 30, 2014.  The increase in DD&A is directly related to the recognition of $34,744 in property impairment in California offset by lower hydrocarbon production volumes in both Kentucky and California.  On a BOE basis, DD&A and impairment represented $17.99 and $14.75 per barrel for the three months ended November 30, 2015 and 2014, respectively.  DD&A expenses represented 30.7% of total operating expenses for the three months ended November 30, 2015.


For the three months ended November 30, 2015, G&A expenses increased $18,317 or 8.0% to $248,357 in comparison to $230,040 for the three months ended November 30, 2014.  We received, as Operator in California, administrative overhead reimbursement of $13,322 during the three months ended November 30, 2015 for the East Slopes Project which was used to directly offset certain employee salaries.  We are continuing a program of reducing all of our G&A costs wherever possible.  G&A expenses represented 53.7% of total operating expenses for the three months ended November 30, 2015.


Interest income for the three months ended November 30, 2015 decreased $39,836 or 10.5% to $339,096 in comparison to $378,932 for the three months ended November 30, 2014 due to reduced loan balances on the Note receivable from App Energy.




23






Interest expense for the three months ended November 30, 2015 increased $263,684 or 36.7% to $982,270 in comparison to $718,586 for the three months ended November 30, 2014.  The increase in interest expense is directly related to the modified loan payment terms on our credit facility with Maximilian.  The credit facility activity is discussed further in the discussion of the Maximilian Credit Facility – Amended and Restated Loan Agreement in the MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings).


Due to the nature of our business, we expect that revenues, as well as all categories of expenses, will continue to fluctuate substantially on a quarter-to-quarter and year-to-year basis.  Revenues are dependent upon both hydrocarbon production levels and the price we receive for hydrocarbon sales.  Since June of 2014, there has been a significant decline in the WTI price of crude oil and subsequently in the realized price we receive from oil sales.  This decline in the price of crude oil has had a substantial negative impact on our cash flow from both our Kentucky and California properties.  Production expenses will fluctuate according to the number and percentage ownership of producing wells that we own.  Exploration and drilling expenses will be dependent upon the amount of capital that we have to invest in future development projects, as well as the success or failure of such projects.  Likewise, the amount of DD&A expense will depend upon the factors cited above including the size of our proven reserves base and the market price of energy products.  G&A expenses will also fluctuate based on our current requirements, but will generally tend to increase as we expand the business operations of the Company.  An ongoing goal of the Company is to improve cash flow to cover the current level of G&A expenses and to fund our development drilling programs in California and Kentucky.


Capital Resources and Liquidity


Our primary financial resource is our proven oil reserves base.  Our ability to fund any future capital expenditure programs is dependent upon the prices we receive from oil sales, the success of our exploration and development program in Lawrence County, Kentucky and Kern County, California and the availability of capital resource financing.


The Company has engaged an investment banking firm to assist in securing refinancing of its debt at more favorable terms and implement our development plans in California and Kentucky.


Changes in our capital resources at November 30, 2015 in comparison to February 28, 2015 are set forth in the table below:


 

 

 

 

 

 

 

Increase

 

Percentage

 

November 30, 2015

 

February 28, 2015

 

(Decrease)

 

Change

Cash

$

108,646 

 

$

496,772 

 

$

(388,126)

 

(78.1%)

Current Assets

$

1,354,327 

 

$

2,554,519 

 

$

(1,200,192)

 

(47.0%)

Total Assets

$

10,874,253 

 

$

12,313,061 

 

$

(1,438,808)

 

(11.7%)

Current Liabilities

$

7,205,479 

 

$

8,311,541 

 

$

(1,106,062)

 

(13.3%)

Total Liabilities

$

17,941,058 

 

$

17,497,651 

 

$

443,407 

 

2.5% 

Working Capital Deficit

$

(5,851,152)

 

$

(5,757,022)

 

$

(94,130)

 

(1.6%)


Our working capital deficit decreased $94,130 or 1.6% to $5,851,152 at November 30, 2015 in comparison to $5,757,022 at February 28, 2015.  This decrease in the working capital deficit was due to reclassification of part of the current portion of the Maximilian credit facility debt to non-current debt due to a loan modification with Maximilian during the nine months ended November 30, 2015.  While we have ongoing positive cash flow from our operations in California and Kentucky we have not yet been able to generate sufficient cash flow to cover all of our G&A and interest expense requirements on a consistent basis.


Our business is capital intensive.  Our ability to grow is dependent upon favorably obtaining outside capital and generating cash flows from operating activities necessary to fund our investment activities.  There is no assurance that we will be able to achieve profitability.  Since our future operations will continue to be dependent on successful exploration and development activities and our ability to seek and secure capital from external sources, should we be unable to achieve sustainable profitability this could cause any equity investment in the Company to become worthless.


Major sources of funds in the past for us have included the debt and equity markets, as well as select asset sales.  While we have achieved positive cash flow from operations in Kentucky and California, we will have to rely on these capital markets to fund future operations and growth.  Our business model is focused on acquiring exploration or development properties as well as existing production.  Our ability to generate future revenues and operating cash flow will depend on successful exploration, and/or acquisition of oil and natural gas producing properties, and stabilized hydrocarbon prices, which may very likely require us to continue to raise equity or debt capital from outside sources.




24






Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the decline of hydrocarbon prices, may restrict our ability to obtain needed capital.


The Company’s financial statements for the nine months ended November 30, 2015 have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities in the normal course of business.  Since entering the oil and gas exploration industry, we have mostly incurred quarterly net losses.  As of November 30, 2015, we have an accumulated deficit of $30,087,731 and a working capital deficit of $5,851,152 which raises substantial doubt about our ability to continue as a going concern.


In the current fiscal year, we will continue to seek additional financing for our planned exploration and development activities in both Kentucky and California.  The Company has engaged an investment banking firm to assist in securing refinancing of its debt under more favorable terms and implement its development plans in California and Kentucky.  We plan to obtain financing through various methods, including issuing debt securities, equity securities, or bank debt, or combinations of these instruments, which could result in dilution to existing security holders and increased debt and leverage.  No assurance can be given that we will be able to obtain funding under any loan commitments or any additional financing on favorable terms, if at all.  Sales of interests in our assets may be another source of cash flow.


Cash Flows


Changes in the net funds provided by and (used in) our operating, investing and financing activities are set forth in the table below:


 

Nine Months

 

Nine Months

 

Increase

 

Percentage

 

November 30, 2015

 

November 30, 2014

 

(Decrease)

 

Change

Net cash provided by (used in) operating activities

$

(438,547)

 

$

254,645 

 

$

(693,192)

 

(272.2%)

Net cash provided by (used in) investing activities

$

670,237 

 

$

(3,387,719)

 

$

4,057,956 

 

119.8%

Net cash provided by (used in) financing activities

$

(619,816)

 

$

3,153,669 

 

$

(3,773,485)

 

(119.7%)


Cash Flow Provided by (Used In) Operating Activities


Cash flow from operating activities is derived from the production of our oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances.  For the nine months ended November 30, 2015, we had a cash flow deficit in operating activities of $438,547 in comparison to cash flow provided by operating activities of $254,645 for the nine months ended November 30, 2014.  This decline in operating cash flow of 693,192 or 272.2% is directly related to lower realized hydrocarbon revenues from the sharp decline of approximately 64% in crude oil prices since June of 2014.  Non-cash account balances relating to DD&A; amortization of debt discount and deferred financing costs accounted for a represented $820,338 in aggregate for the nine months ended November 30, 2015.  Changes in our receivables, prepaids and payables balances accounted for a net increase of approximately $623,330 in our cash flow, but were offset by the increase in the net loss of approximately $1.9 million for the nine months ended November 30, 2015.  Variations in cash flow from operating activities may impact our level of exploration and development expenditures.


Cash Flow Provided by (Used in) Investing Activities


Cash flow from investing activities is derived from changes in oil and gas property balances and our lending activities associated with the App Energy loan. Cash flow provided by investing activities for the nine months ended November 30, 2015 was $670,237, a change of $4,057,956 from the $3,387,719 used in investing activities for the nine months ended November 30, 2014.  This change of $4,057,956 was due to less drilling activity because of lower hydrocarbon prices and reduced lending to App Energy for the nine months ended November 30, 2015.  The credit facility and our lending activity to App Energy is discussed further in the MD&A section of this 10-Q report under the caption “Long-Term Borrowings – Maximilian Credit Facility.”


Cash Flow Provided by (Used In) Financing Activities


Cash flow from financing activities is derived from changes in long-term liability account balances or in equity account balances, excluding retained earnings.  Cash used in our financing activities was $619,816 for the nine months ended November 30, 2015 in comparison to cash flow provided by our financing activities of approximately $3.2 million for the nine months ended November 30, 2014.  This change of $3,773,485 was due to less drilling activity because of lower hydrocarbon prices for the nine months ended November 30, 2015 resulting in less borrowing through our credit facility with Maximilian.  The credit facility and our lending activity to App Energy is discussed further in the MD&A section of this 10-Q report discussed further in the discussion of the



25






Maximilian Credit Facility – Amended and Restated Loan Agreement in the MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.


The following discussion is a summary of cash flows provided by, and used in, the Company’s financing activities at November 30, 2015.


Current Debt (Short-Term Borrowings)


Related Party


During the years ended February 29, 2012 and February 28, 2013, the Company’s President and Chief Executive Officer loaned the Company $250,100 in aggregate that was used for a variety of corporate purposes including an escrow requirement on a loan commitment; extension fees on third party loans; and, a reduction of principal on the Company’s credit line with UBS Bank.  These loans are non-interest bearing loans and repayment will be made upon a mutually agreeable date in the future.


Line of Credit


The Company has an existing $890,000 line of credit for working capital purposes with UBS Bank USA (“UBS”), established pursuant to a Credit Line Agreement dated October 24, 2011 that is secured by the personal guarantee of our President and Chief Executive Officer.  At November 30, 2015, the Line of Credit had an outstanding balance of $853,136.  Interest is payable monthly at a stated reference rate of 0.249% + 337.5 basis points and totaled $28,770 for the nine months ended November 30, 2015.  The reference rate is based on the 30 day LIBOR (“London Interbank Offered Rate”) and is subject to change from UBS.


Non-current Debt (Long-Term Borrowings)


12% Subordinated Notes


The Company’s 12% Subordinated Notes (“the Notes”) were issued pursuant to a March 2010 private placement (of which $250,000 was issued to a related party) and accrue interest at 12% per annum, payable semi-annually on January 29th and July 29th.  On January 29, 2015, the company and 12 of the 13 holders of the Notes agreed to extend the maturity date of the Notes for an additional two years to January 29, 2017.  The note principal of $565,000 is payable in full at the amended maturity of the Notes.  Should the Board of Directors, on the maturity date, decide that the payment of the principal and any unpaid interest would impair the financial condition or operations of the Company, the Company may then elect a mandatory conversion of the unpaid principal and interest into the Company’s common stock at a conversion rate equal to 75% of the average closing price of the Company’s common stock over the 20 consecutive trading days preceding December 31, 2016.


12% Notes balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

12% Subordinated Notes

$

315,000 

 

$

315,000 

12% Subordinated Notes, related party

 

250,000 

 

 

250,000 

 

$

565,000 

 

$

565,000 


In conjunction with the Notes private placement, a total of 1,190,000 common stock purchase warrants were issued at a rate of two warrants for every dollar raised through the private placement.  The warrants have an exercise price of $0.14 and an amended expiration date of January 29, 2017.  The 12% Note warrants that have been exercised are set forth in the table below.


Fiscal Period

 

Warrants

Exercised

 

Shares of

Common Stock

Issued

 

Number of

Accredited

Investors

Year Ended February 28, 2014

 

100,000

 

100,000

 

1

Year Ended February 28, 2015

 

50,000

 

50,000

 

1

Nine Months Ended November 30, 2015

 

-

 

-

 

-

Totals

 

150,000

 

150,000

 

2





26






Maximilian Credit Facility


On October 31, 2012, the Company entered into a loan agreement with Maximilian, which provided for a revolving credit facility of up to $20 million, maturing on October 31, 2016, with a minimum commitment of $2.5 million.  The loan had annual interest of 18% and a monthly commitment fee of 0.5%.  The Company also granted Maximilian a 10% working interest in its share of the oil and natural gas leases in Kern County, California.  The relative fair value of this 10% working interest amounting to $515,638 was recognized as a debt discount and is being amortized over the term of the loan.  Amortization expense was $100,896 for the nine months ended November 30, 2015.  Unamortized debt discount amounted to $103,168 at November 30, 2015.


In 2012, the Company also issued 2,435,517 warrants to third parties who assisted in the closing of the loan.  The warrants have an exercise price of $0.044; contain a cashless exercise provision; have piggyback registration rights; and are exercisable for a period of five years expiring on October 31, 2017.  The fair value of the warrants, as determined by the Black-Scholes option pricing model, was $98,084 and included the following assumptions: a risk free interest rate of 0.72%; stock price of $0.04, volatility of 153.44%; and a dividend yield of 0.0%.  The fair value of the warrants was recognized as a financing cost and is being amortized as a part of deferred financing cost over the term of the loan.  As of November 30, 2015, 316,617 of these warrants remain unexercised.


Maximilian Credit Facility - Amended and Restated Loan Agreement


In connection with the Company’s acquisition of a working interest from App in the Twin Bottoms Field in Lawrence County, Kentucky, the Company amended its loan agreement with Maximilian on August 28, 2013.  The amended loan agreement provided for an increase in the revolving credit facility from $20 million to $90 million and a reduction in the annual interest rate from 18% to 12%.  The monthly commitment fee of 0.5% per month on the outstanding principal balance remained unchanged.  Advances under the amended loan agreement will mature on August 28, 2017.  The obligations under the amended loan agreement continue to be secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on the Company’s leases in Kern County, California.  The amended loan agreement also provided for the revolving credit facility to be divided into two borrowing sublimits.  The first borrowing sublimit is $50 million and is for borrowing by the Company, primarily for its ongoing oil and natural gas exploration and development activities.  The second borrowing sublimit, of $40 million, is for loans to be extended by the Company, as lender, to App, as borrower pursuant to a Loan and Security Agreement entered into between the Company and App on August 28, 2013 (See Note 8 – Note Receivable).


The amended loan agreement contains customary covenants for loan of such type, including among other things, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The amended loan agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of the Company’s obligations under the amended loan agreement could be accelerated by Maximilian, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.


As consideration for Maximilian facilitating the Company’s transactions with App and entering into the amended loan agreement, the Company (a) issued to Maximilian approximately 6.1 million common shares, representing 9.99% of the Company’s outstanding common stock on a fully-diluted basis at the time of grant, and (b) issued approximately 6.1 million warrants to purchase shares of the Company’s common stock representing the right to purchase up to an additional 9.99% of the Company’s outstanding common stock on a fully-diluted basis, calculated as of the date of grant.  The warrants have an exercise price of $0.10; contain a cash exercise provision and are exercisable for a period of three years expiring on August 28, 2016; and contain an exercise blocker provision that prevents any exercise of the warrants if such exercise and related issuance of common stock would increase the Maximilian holdings of the Company’s common stock to more than 9.99% of the Company’s currently issued and outstanding shares at the time of the exercise.  The Company also granted to Maximilian a 50% net profits interest in the Company’s 25% working interest, after the Company recovers its investment, in the Company’s working interest in its Kentucky acreage, pursuant to an Assignment of Net Profits Interest entered into as of August 28, 2013 by and between the Company and Maximilian.


On May 28, 2014 at Maximilian’s request, the Company finalized a share-for-warrant exchange agreement in which Maximilian returned to the Company 427,729 common shares and was in turn issued the same number of warrants containing the same provisions as the originally issued warrants.  This share-for-warrant exchange occurred so that Maximilian would hold no more than 9.99% of the Company’s common shares issued and outstanding.  The Company determined that the share-for-warrant exchange did not result in any incremental fair value.




27






On August 21, 2014, the Company entered into a First Amendment to Amended and Restated Loan and Security Agreement and Share Repurchase Agreement (the “First Amendment”) with Maximilian.  The First Amendment secured for the Company an additional advance of $2,200,000 under its credit facility with Maximilian since the advances made by Maximilian had already exceeded its minimum funding commitment. Additionally, Maximilian agreed to temporarily decrease the required monthly payment made by the Company until it has paid $1,000,000 less than the principal payments required by the previous agreement.  Furthermore, Maximilian agreed to reduce the regular interest rate applicable to the loan from 12% per annum to 9% per annum and the default interest rate by 3%.


The additional advance, the reduction in the required monthly payment and the reduction in the interest rate were facilitated through the company’s acquisition of 5,694,823 shares of our common stock held by Maximilian.  The repurchased shares were cancelled and restored to the status of authorized, but unissued stock.  The Company paid for the share repurchase transaction through an advance of $1,708,447 under the existing loan agreement with Maximilian.


On May 20, 2015, the Company entered into a Second Amendment to Amended and Restated Loan and Security Agreement (the “Second Amendment”) with Maximilian.  The Second Amendment modified the calculation of the required monthly payment for a three-month period ending June 30, 2015.  As consideration for entering into the loan modification, the Company agreed to lower the exercise price of the warrants Maximilian currently holds from $0.10 to $0.04.  No other terms of the warrant agreement were changed.


On October 14, 2015, the Company entered into a Third Amendment to the Amended and Restated Loan and Security Agreement and Second Warrant Amendment with Maximilian, (the “Third Amendment”).  Pursuant to the Third Amendment, Maximilian agreed to a reduction in the Company’s monthly payments under the loan agreement to $50,000 per month for a period of six months ending on February 29, 2016.  The reduction in monthly payments allows for additional funds to be used by the Company in drilling and completing additional wells in Kentucky.  As consideration for the reduction in the monthly payment amount, the Company agreed that twenty percent of the amount by which the monthly payment was reduced would be added to the loan balance, and the portion of the monthly payment savings that constitutes savings in interest or commitment fees would be treated as an additional advance of principal under the loan agreement (the “Deemed Advances”).  The Company also agreed to grant to Maximilian an overriding royalty interest of 1.5% of its working interest in four wells in Kentucky.  As part of the Third Amendment, the Company also agreed to extend the expiration date of the warrants held by Maximilian to purchase up to 6,550,281 shares of common stock of the Company to August 28, 2018.  The Company determined that the modification of the warrant expiration date did not result in any incremental fair value.


With the assistance of Maximilian, the Company is currently working with an investment banking firm to assist in securing refinancing of its debt with Maximilian, since the long-term commitment needed to develop the Kentucky and California projects no longer fits the Maximilian business model.  Maximilian is continuing to work with the Company in modifying the credit facility terms during this period of lower hydrocarbon prices.


Current debt balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Maximilian note

$

3,419,074 

 

$

4,823,325 

Maximilian note discount

 

(103,168)

 

 

(132,114)

 

$

3,315,906 

 

$

4,691,211 


Non-current debt balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Maximilian note

$

10,138,706 

 

$

8,663,458 

Maximilian note discount

 

 

 

(71,951)

 

$

10,138,706 

 

$

8,591,507 


App Loan Agreement


In connection with amending and restating its loan agreement with Maximilian, on August 28, 2013 the Company extended to App Energy, LLC, a Kentucky limited liability company (“App Energy”) a credit facility for the development of a shallow oil project in an existing natural gas field in Lawrence County, Kentucky pursuant to a Loan and Security Agreement between the Company as lender and App Energy as borrower (the “App Loan Agreement”).




28






The App Loan Agreement provides for a revolving credit facility of up to $40 million, maturing on August 28, 2017, with a minimum commitment of $2.65 million (the “Initial Advance”).  All funds advanced to App Energy, as borrower, by Daybreak, as lender, are to be borrowed by Daybreak under its Amended Loan Agreement with Maximilian.  The Initial Advance bears interest at a rate per annum equal to 16.8%, and subsequent loans under the Loan Agreement bear interest at a rate per annum equal to 12%.  The App Loan Agreement also provides for a monthly commitment fee of 0.6% per month of the outstanding principal balance of the loans.  The obligations under the App Loan Agreement are secured by a perfected first priority security interest in substantially all of the assets of App Energy, including the App Energy leases in Lawrence County, Kentucky.


The proceeds of the initial borrowing by App Energy of $2.65 million under the App Energy facility were primarily used to (a) pay loan fees and closing costs, (b) repay indebtedness and (c) finance the drilling of three wells by App Energy in the Twin Bottoms Field in Lawrence County, Kentucky in which the Company has a 25% working interest.  Future advances under the facility will primarily be used for oil and natural gas exploration and development activities.


The App Loan Agreement contains customary covenants for loan of such type, including, among other things, covenants that restrict App Energy’s ability to make capital expenditures, incur indebtedness, incur liens and dispose of property.  The App Loan Agreement also contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations and bankruptcy or insolvency.  If an event of default occurs, all of App Energy’s obligations under the App Loan Agreement could be accelerated by the Company, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.


In connection with the App Loan Agreement, App Energy also granted to the Company a 25% working interest in approximately 6,400 acres (currently 7,300 acres) in two large contiguous blocks in the Twin Bottoms Field in Lawrence County, Kentucky and entered into a corresponding promissory note and a Mortgage, Leasehold Mortgage, Assignment of Production, Security Agreement and Financing Statement, both dated as of August 28, 2013.  App Energy’s manager, John A. Piedmonte, Jr., also entered into a limited Indemnity Agreement in connection with the loan.  The loans under the App Loan Agreement are also guaranteed by certain of App Energy’s affiliates.


In connection with entering into the Third Amendment with Maximilian, the Company concurrently entered into a Third Amendment to Loan and Security Agreement with App Energy (the “App Amendment”), which amended the Company’s loan agreement with App Energy in which the Company, as lender, lends to App Energy, as borrower, a portion of the advances it receives pursuant to its loan agreement with Maximilian.  The App Amendment provides for a reduction in interest rate and a reduction in monthly payments to be made by App Energy to the Company for the same payment cycles as the reduced payment to be made by the Company under the Maximilian Amendment.  The reduction in monthly payments by App Energy will allow App Energy to fund its share of drilling and completing additional wells in Kentucky with the Company.  As consideration for the reduction in the monthly payment amount, App Energy agreed that certain amounts will be treated as additional advances under the App Energy loan agreement, and that it would fund a portion of the Company’s drilling and development expenses with respect to two wells.  App Energy also agreed to grant to Maximilian an overriding royalty interest on the same terms as the overriding royalty interest agreed to by the Company.  


Note receivable balances at November 30, 2015 and February 28, 2015 are set forth in the table below:


 

November 30, 2015

 

February 28, 2015

Note receivable – current

$

642,540

 

$

1,320,944

Note receivable – non-current

 

3,738,296

 

 

3,429,056

 

$

4,380,836

 

$

4,750,000


Capital Commitments


Daybreak has ongoing capital commitments to develop certain leases pursuant to their underlying terms.  Failure to meet such ongoing commitments may result in the loss of the right to participate in future drilling on certain leases or the loss of the lease itself.  These ongoing capital commitments may also cause us to seek additional capital from sources outside of the Company.  The current uncertainty in the credit and capital markets, and the economic downturn, may restrict our ability to obtain needed capital.





29






Encumbrances


The Company’s debt obligations, pursuant to the loan agreement with Maximilian, are secured by a perfected first priority security interest in substantially all of the personal property of the Company, and a mortgage on our leases in Kern County, California encompassing the Sunday, Bear, Black, Ball and Dyer Creek properties.  For further information on the loan agreement refer to the discussion of the Maximilian Credit Facility – Amended and Restated Loan Agreement in the  MD&A section of this 10-Q report under Capital Resources and Liquidity – Cash Flow Provided by (Used in) Financing Activities, Non-current Debt (Long-term Borrowings) in this MD&A.


Restricted Stock and Restricted Stock Unit Plan


On April 6, 2009, the Board approved the Restricted Stock and Restricted Stock Unit Plan (the “2009 Plan”) allowing the executive officers, directors, consultants and employees of Daybreak and its affiliates to be eligible to receive restricted common stock and restricted common stock unit awards.  Subject to adjustment, the total number of shares of Daybreak common stock that will be available for the grant of awards under the 2009 Plan may not exceed 4,000,000 shares; provided, that, for purposes of this limitation, any stock subject to an award that is forfeited in accordance with the provisions of the 2009 Plan will again become available for issuance under the 2009 Plan.  We believe that awards of this type further align the interests of our employees and our shareholders by providing significant incentives for these employees to achieve and maintain high levels of performance.  Restricted stock and restricted stock units also enhance our ability to attract and retain the services of qualified individuals.


At November 30, 2015, a total of 3,000,000 shares of restricted stock had been awarded and remained outstanding under the 2009 Plan, with 2,986,220 shares having fully vested.  A total of 1,013,780 common stock shares remained available at August 31, 2015 for issuance pursuant to the 2009 Plan.  A summary of the 2009 Plan issuances is set forth in the table below:


Grant

Date

 

Shares

Awarded

 

Vesting

Period

 

Shares

Vested(1)

 

Shares

Returned(2)

 

Shares

Outstanding

(Unvested)

4/7/2009

 

1,900,000

 

3 Years

 

1,900,000

 

-

 

-

7/16/2009

 

25,000

 

3 Years

 

25,000

 

-

 

-

7/16/2009

 

625,000

 

4 Years

 

619,130

 

5,870

 

-

7/22/2010

 

25,000

 

3 Years

 

25,000

 

-

 

-

7/22/2010

 

425,000

 

4 Years

 

417,090

 

7,910

 

-

 

 

3,000,000

 

 

 

2,986,220(1)

 

13,780(2) 

 

-


(1)

Does not include shares that were withheld to satisfy such tax liability upon vesting of a restricted award by a Plan Participant, and subsequently returned to the 2009 Plan.

(2)

Reflects the number of common shares that were withheld pursuant to the settlement of the number of shares with a fair market value equal to such tax withholding liability, to satisfy such tax liability upon vesting of a restricted award by a Plan Participant.


For the nine months ended November 30, 2015, the Company did not recognize any stock compensation expense related to the above restricted stock grants since all issuances have been fully amortized.


Management Plans to Continue as a Going Concern


We continue to implement plans to enhance Daybreak’s ability to continue as a going concern.  The Company currently has a net revenue interest in 20 producing wells in its East Slopes Project located in Kern County, California (the “East Slopes Project”).  The revenue from these wells has created a steady and reliable source of revenue.  The Company’s average working interest in these wells is 36.6% with an average net revenue interest of 28.5% for these same wells.  Additionally, Daybreak currently has a net revenue interest in 14 producing horizontal oil wells in the Twin Bottoms Field in Lawrence County, Kentucky.  Our average working interest in these 14 wells is 22.6% with an average net revenue interest of 19.7%.


We anticipate revenues will continue to increase as the Company participates in the drilling of more wells in Kentucky and California.  Daybreak plans to continue its development drilling program at a rate that is compatible with its cash flow, funding opportunities and hydrocarbon prices.





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The Company’s sources of funds in the past have included the debt and equity markets and select asset sales.  The Company has experienced revenue growth from its oil properties, however, it has not yet established a consistent positive cash flow on a company-wide basis.  It will be necessary for the Company to obtain additional funding from the private or public debt or equity markets in the future.  However the Company cannot offer any assurance that the Company will be successful in executing the aforementioned plans to continue as a going concern.


Critical Accounting Policies


Refer to Daybreak’s Annual Report on Form 10-K for the fiscal year ended February 28, 2015.


Off-Balance Sheet Arrangements


As of November 30, 2015, we did not have any off-balance sheet arrangements or relationships with unconsolidated entities or financial partners that have been, or are reasonably likely to have, a material effect on our financial position or results of operations.




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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


As a smaller reporting company, we are not required to provide the information otherwise required by this Item.



ITEM 4.  CONTROLS AND PROCEDURES


Management’s Evaluation of Disclosure Controls and Procedures


As of the end of the reporting period, November 30, 2015, an evaluation was conducted by Daybreak management, including our President and Chief Executive Officer, who is also serving as our interim principal finance and accounting officer, as to the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(e) of the Exchange Act.  Such disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods specified by the SEC rules and forms.  Additionally, it is vital that such information is accumulated and communicated to our management, including our President and Chief Executive Officer, in a manner to allow timely decisions regarding required disclosures.  Based on that evaluation, our management concluded that our disclosure controls were effective as of November 30, 2015.


Changes in Internal Control over Financial Reporting


There have not been any changes in the Company’s internal control over financial reporting during the nine months ended November 30, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


Limitations


Our management does not expect that our disclosure controls or internal controls over financial reporting will prevent all errors or all instances of fraud.  A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met.  Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.


Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.  These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake.  Controls can also be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls.  The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and any design may not succeed in achieving its stated goals under all potential future conditions.


Over time, controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with policies or procedures.  Because of the inherent limitation of a cost-effective control system, misstatements due to error or fraud may occur and not be detected.




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PART II

OTHER INFORMATION



ITEM 1.  LEGAL PROCEEDINGS


None



ITEM 1A.  RISK FACTORS


In addition to the other information set forth in this Form 10-Q Report, you should carefully consider the various factors discussed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended February 28, 2015, which could materially affect our business, financial condition or future results. Our Annual Report is available from the SEC at www.sec.gov.  The risks described in this report are not the only risks we face.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial could have a material adverse effect on our business, financial condition or future results of operations.








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ITEM 6.  EXHIBITS


The following Exhibits are filed as part of the report:


Exhibit

Number

Description



10.20(1)

Third Amendment to Amended and Restated Loan and Security Agreement and Second Warrant Amendment, dated October 14, 2015, by and between Daybreak Oil and Gas, Inc. and Maximilian Resources LLC, a Delaware limited liability company.


10.21(1)

Third Amendment to Loan and Security Agreement, dated October 14, 2015, by and between Daybreak Oil and Gas, Inc. and App Energy, LLC, a Kentucky limited liability company.


31.1(1)

Certification of principal executive and principal financial officer as required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.


32.1(1)

Certification of principal executive and principal financial officer as required pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


101.INS(2)

XBRL Instance Document


101.SCH(2)

XBRL Taxonomy Schema


101.CAL(2)

XBRL Taxonomy Calculation Linkbase


101.DEF(2)

XBRL Taxonomy Definition Linkbase


101.LAB(2)

XBRL Taxonomy Label Linkbase


101.PRE(2)

XBRL Taxonomy Presentation Linkbase






(1)

Filed herewith.

(2)

Furnished herewith




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SIGNATURES


Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


DAYBREAK OIL AND GAS, INC.

 

 

By:

/s/ JAMES F. WESTMORELAND

 

James F. Westmoreland, its

 

President, Chief Executive Officer and interim

 

principal finance and accounting officer

 

(Principal Executive Officer, Principal Financial

 

Officer and Principal Accounting Officer)

 

 

Date:  January 13, 2016









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